The present application relates to systems and methods for measuring the amount of one phase in a mixture of phases, and more particularly to measuring the amount of water present in crude petroleum oil when the salinity of the water can vary.
The following paragraphs contain some discussion, which is illuminated by the innovations disclosed in this application, and any discussion of actual or proposed or possible approaches in these paragraphs does not imply that those approaches are prior art.
The chemical and physical characterization of crude, partially refined, and fully refined petroleum products is a common practice in the petroleum industry. Characterizations such as compositional and physical property determinations are used for a variety of purposes. One of their more important uses is when they are done in combination with hydrocarbon well testing to assist in optimizing oil production from a single or series of hydrocarbon wells. Another important use is during the transfer of crude petroleum oil, as occurs during the production, transport, refining, and sale of oil. The accurate determination of water content and validation of the amount of water in crude oil is particularly important during the taxation of crude oil and the sale of crude oil, where the owner or seller of the oil does not want to pay taxes on water and the customer does not want to pay the price of oil for water. For example, it is well know to a person having ordinary skill in the art of petroleum engineering that crude petroleum oil emerging from production wells can contain large amounts of water, ranging from generally about 1% to as high as about 99% water. This value is known as the water cut (“WC”).
During operation of a high water cut oil well, the oil and water mixture can ideally be considered as a dispersion of oil in water wherein the water is the continuous phase and the oil exists as droplets within the continuous water phase. At water cuts above about 80%, the water is usually the continuous phase and so droplets of the oil are dispersed within the water phase. Additionally, a high water cut oil well typically produces oil with a daily average water cut that can shift over several days or weeks of operation. This is especially true as the oil-bearing formation becomes depleted of oil, resulting in higher and higher amounts of water exiting from the well. However, an oil well is not an ideal system and its compositional behavior can be quite dynamic and random over a period of time as short as several seconds or minutes. For example, water flooding (e.g. water injection from above the ground down into the subterranean oil-bearing formations) can be used to push and carry oil up to the surface of the Earth. At any given moment, more or less water can enter the oil well drill string. This can cause variation in the amount of water in the flow stream exiting from the well. Additionally, as the oil and water mixture travels up the drill string (which can be as long as a mile or more), oil droplets can coalesce into larger collections, or “slugs”, of oil. A slug of oil can be considered to be a high concentration of oil with a reduced level of entrained water. Such coalescence of oil then can cause variation in the amount of water exiting a well at any given moment. During operation of a well experiencing oil coalescence, slugs of oil with reduced amounts of water and slugs of water with reduced amounts of dispersed oil can exit from the well. Thus, a water content determination system in contact with the discharge of such a well will be measuring the water content of such slugs.
Water content determinations and validations can be conducted on-line and off-line during petroleum processing. On-line determinations include instruments such as densitometers, capacitance probes, radio frequency probes, and electromagnetic characterization systems, including those which are referred to, for historical reasons, as “microwave analyzers”.
U.S. Pat. No. 4,862,060 to Scott (the '060 patent), entitled Microwave Apparatus for Measuring Fluid Mixtures and which is hereby incorporated by reference, discloses electromagnetic characterization systems and methods which are most suitable for monitoring water percentages when the water is dispersed in a continuous oil phase. U.S. Pat. No. 4,996,490 to Scott (the '490 patent), entitled Microwave Apparatus and Method for Measuring Fluid Mixtures and which is hereby incorporated by reference, discloses electromagnetic characterization apparatuses and methods for monitoring water percentages when either oil or water is the continuous oil phase. For the example of oil and water mixtures, the '490 patent discloses that whether a particular mixture exists as an oil-in-water or a water-in-oil dispersion can be determined by differences in the reflected microwave power curves in the two different states of the same mixture. Therefore, the '490 patent discloses magnetic characterization apparatuses and methods, including the ability to measure microwave radiation power loss and reflection to detect the state of the dispersion. In further embodiments of that invention, methods are disclosed to compare the measured reflections and losses to reference reflections and losses to determine the state of the mixture as either water-in-oil or oil-in-water, which then allows the proper selection and comparison of reference values relating the measured microwave oscillator frequency to the percentage water. An embodiment of the '490 patent is reproduced from that patent in FIG. 1A.
Salinity in the water associated with crude oil presents a further challenge to such water cut determination systems and methods because salinity has a significant effect on the electromagnetic properties of the oil and water mixture. Additionally, the amount of salinity in the water can vary, even from the same well. For example, water percolation within subterranean oil-bearing formations can change course over time resulting in changing amounts of dissolved salts in the water. One method of correcting for the effects of salinity changes is for an operator to manually measure the salinity of the water phase and input the measurement into the analyzer to allow it to select pre-established offset correction factors, based on the inputted salinity and test-generated calibration curves. A manual determination of salinity is commonly made using a refractometer to measure the refractive index of the water phase. This index is then correlated to % salinity using a pre-established relationship between % salinity and refractive index. The % salinity is then entered into the analyzer as previously described. The pre-established relationship between % salinity and refractive index can be developed by measuring the refractive index of a series of standardized saline solutions to establish a data reference set and equations can be fitted to the data set.
Sometimes, the refractive index of the aqueous phase cannot be easily determined. For example, the aqueous phase may be so turbid as to prevent an accurate reading from being obtained. Or, in the case of an emulsified oil-water system, the refractive index cannot be read unless the system is somehow de-emulsified and allowed to separate into a clear-enough aqueous phase to allow a refractive index to be determined.
Such refractive index measurement techniques or other separate salinity measurement techniques are thus inherently unreliable in systems that are susceptible to emulsification and require additional apparatus, further complicating the total measurement system.
Other laboratory methods will analyze the produced water for ionic content and a “total dissolved solids” and the “equivalent NaCl” contents can be determined. Since different salts, e.g. NaCl, KCl, etc. all have different conductivities (and these change with electromagnetic frequency), it is difficult to know what number is appropriate to use. Many times the “total dissolved salts” will be used as equivalent NaCl. These numbers are inexact and will lead to real time errors of measurement. In addition, the samples are always at room temperature and do not reflect the conductivity of the ion at the operating temperature of the production fluids. Additionally, such off-line methods do not offer the advantage of automatic and continuous monitoring.
One approach to accommodate the effects of variable salinity is to use a joint densitometry and electromagnetic characterization system and method. See U.S. patent application Ser. No. 11/490,541, entitled “Autocalibrated Multiphase Fluid Characterization Using Extrema of Time Series,” by Bentley N. Scott, filed Jul. 20, 2006, Patent Publication Document Number US 2007-0038399 A1. The '541 application is a dual instrument approach. An approach using only a single instrumental method such as a single electromagnetic characterization system (e.g. a single microwave analyzer) is also desirable.